NMR logging apparatus and methods for fluid typing

ABSTRACT

A novel method and apparatus is disclosed for the separation of fluid phases in borehole measurements. The method is based on selecting an optimum contrast mechanism and a corresponding set of measurement parameters for a particular borehole environment. The contrast mechanism can be based on, among others, diffusion, relaxation time or hydrogen index differences between different types of fluids. Once an initial measurement is made, the measurement parameters are compared to a predetermined set of values to broadly estimate the types of fluids present in the geologic environment. If necessary, the measurement is repeated to obtain optimal fluid typing for the estimated fluid types.

[0001] This application claims priority of application Ser. No.09/429,293, filed on Oct. 28, 1999, which claims priority of provisionalapplication Ser. No. 60/106,259, filed on Oct. 30, 1998. The content ofthe above applications is incorporated herein by reference.

FIELD OF THE INVENTION

[0002] The present invention relates to nuclear magnetic resonance (NMR)borehole measurements and more particularly to fluid typing based onseparation of signals from different fluids using user-adjustedmeasurement parameters.

BACKGROUND

[0003] The ability to differentiate between individual fluid types isone of the main concerns in the examination of the petrophysicalproperties of a geologic formation. For example, in the search for oilit is important to separate signals due to producible hydrocarbons fromthe signal contribution of brine, which is a fluid phase of littleinterest. Extremely valuable is also the capability to distinguish amongdifferent fluid types, in particular, among clay-bound water,capillary-bound water, movable water, gas, light oil, medium oil, andheavy oil. However, so far no approach has been advanced to reliablyperform such fluid typing in all cases.

[0004] In evaluating the hydrocarbon production potential of asubsurface formation, the formation is described in terms of a set of“petrophysical properties.” Such properties may include: (1) thelithology or the rock type, e.g., amount of sand, shale, limestone, ormore detailed mineralogical description, (2) the porosity or fraction ofthe rock that is void or pore space, (3) the fluid saturations orfractions of the pore space occupied by oil, water and gas, and others.Various methods exist for performing measurements of petrophysicalproperties in a geologic formation. Nuclear magnetic resonance (NMR)logging, which is the focus of this invention, is among the best methodsthat have been developed for a rapid determination of such properties,which include formation porosity, composition of the formation fluid,the quantity of movable fluid and permeability, among others. At leastin part this is due to the fact that NMR measurements areenvironmentally safe. Importantly, NMR logs differ from conventionalneutron, density, sonic, and resistivity logs in that NMR logs areessentially unaffected by matrix mineralogy, i.e., provide informationonly on formation fluids. The reason is that NMR signals from the matrixdecay too quickly to be detected by the current generation NMR loggingtools. However, such tools are capable of directly measuring rockporosity filled with the fluids. Even more important is the uniquecapability of NMR tools, such as NUMAR's MRIL® tool, to distinguishamong different fluid types, in particular, clay-bound water,capillary-bound water, movable water, gas, light oil, medium oil, andheavy oil by applying different sets of user-adjusted measurementparameters.

[0005] To better appreciate how NMR logging can be used for fluid signalseparation, it is first necessary to briefly examine the type ofparameters that can be measured using NMR techniques. NMR logging isbased on the observation that when an assembly of magnetic moments, suchas those of hydrogen nuclei, are exposed to a static magnetic field theytend to align along the direction of the magnetic field, resulting inbulk magnetization. The rate at which equilibrium is established in suchbulk magnetization upon provision of a static magnetic field ischaracterized by the parameter T₁, known as the spin-lattice relaxationtime. Another related and frequently used NMR logging parameter is thespin-spin relaxation time T₂ (also known as transverse relaxation time),which is an expression of the relaxation due to non-homogeneities in thelocal magnetic field over the sensing volume of the logging tool. Bothrelaxation times provide information about the formation porosity, thecomposition and quantity of the formation fluid, and others.

[0006] Another measurement parameter obtained in NMR logging is thediffusion of fluids in the formation. Generally, diffusion refers to themotion of atoms in a gaseous or liquid state due to their thermalenergy. Self-diffusion is inversely related to the viscosity of thefluid, which is a parameter of considerable importance in boreholesurveys. In a uniform magnetic field, diffusion has little effect on thedecay rate of the measured NMR echoes. In a gradient magnetic field,however, diffusion causes atoms to move from their original positions tonew ones, which moves also cause these atoms to acquire different phaseshifts compared to atoms that did not move. This effect contributes to afaster rate of relaxation in a gradient magnetic field.

[0007] NMR measurements of these and other parameters of the geologicformation can be done using, for example, the centralized MRIL® toolmade by NUMAR, a Halliburton company, and the sidewall CMR tool made bySchlumberger. The MRIL® tool is described, for example, in U.S. Pat. No.4,710,713 to Taicher et al. and in various other publications including:“Spin Echo Magnetic Resonance Logging: Porosity and Free Fluid IndexDetermination,” by Miller, Paltiel, Millen, Granot and Bouton, SPE20561, 65th Annual Technical Conference of the SPE, New Orleans, La.,Sep. 23-26, 1990; “Improved Log Quality With a Dual-Frequency Pulsed NMRTool,” by Chandler, Drack, Miller and Prammer, SPE 28365, 69th AnnualTechnical Conference of the SPE, New Orleans, La., Sep. 25-28, 1994.Details of the structure and the use of the MRIL® tool, as well as theinterpretation of various measurement parameters are also discussed inU.S. Pat. Nos. 4,717,876; 4,717,877; 4,717,878; 5,212,447; 5,280,243;5,309,098; 5,412,320; 5,517,115, 5,557,200 and 5,696,448, all of whichare commonly owned by the assignee of the present invention. TheSchlumberger CMR tool is described, for example, in U.S. Pat. Nos.5,055,787 and 5,055,788 to Kleinberg et al. and further in “Novel NMRApparatus for Investigating an External Sample,” by Kleinberg, Sezginerand Griffin, J. Magn. Reson. 97, 466-485, 1992. The content of the abovepatents is hereby incorporated by reference; the content of thepublications is incorporated by reference for background.

[0008] It has been observed that the mechanisms determining the measuredvalues of T₁, T₂ and diffusion depend on the molecular dynamics of theformation being tested and on the types of fluids present. Thus, in bulkvolume liquids, which typically are found in large pores of theformation, molecular dynamics is a function of both molecular size andinter-molecular interactions, which are different for each fluid. Water,gas and different types of oil each have different T₁, T₂ anddiffusivity values. On the other hand, molecular dynamics in aheterogeneous media, such as a porous solid that contains liquid in itspores, differs significantly from the dynamics of the bulk liquid, andgenerally depends on the mechanism of interaction between the liquid andthe pores of the solid media. It will thus be appreciated that a correctinterpretation of the measured signals can provide valuable informationrelating to the types of fluids involved, the structure of the formationand other well-logging parameters of interest.

[0009] It should be clear that the quality of the fluid typing dependson the magnitudes of the contrasts between measurement signals fromdifferent fluid types. Generally, as the contrasts increase, the qualityof the typing improves. Table 1 below shows the ranges of thecharacteristic parameters for brine, gas, and oil measured by an MRIL®—Ctool under typical reservoir conditions (i.e., pressure (P) from 2,000to 10,000 psi, and temperature (T) from 100 to 350° F.). Table 2 showstypical parameter values for a Gulf of Mexico sandstone reservoir. Theinformation in the tables clearly reveals a broad distribution for T₁,T₂, D, and hydrogen index (HI) that is used in accordance with thepresent invention in fluid typing. TABLE 1 Ranges of the characteristicparameters of water, gas, and oil measured with an MRIL ®-C tool undertypical reservoir conditions Free Water Bound Water Gas Oil HydrogenIndex (HI) ˜1 ˜1 <1 <˜1 Diffusion (D) medium very low very high lowRelaxation Time (T₁) medium short long long Relaxation Time (T₂) mediumshort short long

[0010] TABLE 2 Typical values of characteristic parameters for fluids ina Gulf of Mexico sandstone reservoir T₁ T₂ D₀ × 10⁻⁵ D₀ T₁ (ms) (ms) HIcm²/s cm² Brine 1-500 0.67-200 1 7.7 0.0077-4.0 Oil 5,000 460 1 7.9  40Gas 4,400  40 0.38 100 440

[0011] Despite the existing contrasts, a problem encountered in standardNMR measurements is that in some cases signals from different fluidphases cannot be fully separated. For example, NMR signals due to brine,which is of no interest to oil production, cannot always be separatedfrom signals due to producible hydrocarbons. The reason is that for aparticular measurement parameter there is an overlap in the ranges ofthe measured signals from these fluids.

[0012] Several methods for acquiring and processing gradient NMR welllog data have been proposed recently that enable the separation ofdifferent fluid types. These separation methods are based primarily onthe existence of a T₁ contrast and a diffusion contrast in NMRmeasurements of different fluid types. Specifically, a T₁ contrast isdue to the fact that light hydrocarbons have long T₁ times, roughly 1 to3 seconds, whereas T₁ values longer than 1 second are unusual forwater-wet rocks. In fact, typical T₁'s are much shorter than 1 sec, dueto the typical pore sizes encountered in sedimentary rocks, providing aneven better contrast.

[0013] Diffusion in gradient magnetic fields provides a separatecontrast mechanism applicable to T₂ measurements that can be used tofurther separate the long T₁ signal discussed above into its gas and oilcomponents. In particular, at reservoir conditions the self-diffusioncoefficient Do of gases, such as methane, is at least 50 times largerthan that of water and light oil, which leads to proportionately shorterT₂ relaxation times associated with the gas. Since diffusion has noeffect on the T₁ measurements, the resulting diffusion contrast can beused to separate oil from gas.

[0014] The T₁ and diffusion contrast mechanisms have been used to detectgas and separate fluid phases in what is known as the differentialspectrum method (DSM) proposed first in 1995. There are several problemsassociated with prior art methods, such as DSM. For example, generallyDSM requires a logging pass associated with relatively long wait times(T_(W) approximately 10 sec) so that DSM-based logging is relativelyslow. Further, the required T₁ contrast may disappear in wells drilledwith water-based mud, even if the reservoir contains light hydrocarbons.This can happen because water from the mud invades the big pores first,pushing out the oil and thus adding longer T₂'s to the measurementspectrum. In such cases, DSM or standard NMR time domain analysis (TDA)methods have limited use either because there is no separation in the T₂domain, or because the two phases are too close and can not be pickedrobustly. Separation problems similar to the one described above canalso occur in carbonate rocks. In carbonates an overlap between thebrine and hydrocarbons phases is likely because the surface relaxivityin carbonates is approximately ⅓ that of sandstones. In other words, forthe same pore size, he surface relaxation in carbonates is about 3 timeslonger than that for a sandstone, such weak surface relaxation causingan overlap between the observable fluid phases. Additional problem forcarbonates is the presence of vugs. Water bearing vugs, because of heirlarge pore sizes, have long T₂'s and can easily be interpreted as oil byprior art techniques. No single technique seems to solve these and otherproblems encountered in standard logging practice.

[0015] It is apparent, therefore, that there is a need for a flexibleapparatus and methods, using different contrast mechanisms, in whichthese and other problems associated with fluid typing in the prior artare obviated.

SUMMARY OF THE INVENTION

[0016] The present invention is based on using a combination of severaldifferent contrast mechanisms in NMR fluid typing measurements of ageologic formation. To this end, in accordance with the presentinvention, dependent on the specifics of the geologic formation themeasurement tool uses different sets of NMR measurement parameters so asto select the optimum contrast mechanism for fluid typing. The contrastmechanisms used in a preferred embodiment include T₁, T₂, D, HI, andviscosity η contrasts, which are fundamental to fluid typing. In apreferred embodiment, the present invention uses Numar Corporation'sMRIL® tool because of its capability to make multi-contrastmeasurements. Appropriate selection of pulse sequences, such as CPMG,and acquisition parameters, such as pulse waiting time (T_(W) ) and echospacing time (TE), allows the acquisition of weighted spin echo datawith different contrasts.

[0017] In particular, in accordance with a preferred embodiment, amethod for fluid typing of a geological environment is disclosed, usingnuclear magnetic resonance (NMR) measurements. The method comprises:determining a set of parameters for a gradient NMR measurement,obtaining a pulsed NMR log using the determined set of parameters; andselecting from the NMR log an optimum contrast mechanism andcorresponding measurement parameters for fluid typing of the geologicalenvironment. In a preferred embodiment, the set of determined parameterscomprises the interecho spacing TE of a pulsed NMR sequence, themagnetic field gradient G and the wait time T_(w) of the NMRmeasurement. Further, in a preferred embodiment, the optimum contrastmechanism used in the method is based on diffusion, relaxation orhydrogen index contrast.

[0018] In another aspect of this invention, a method for fluid typing ofa geological environment is disclosed using nuclear magnetic resonance(NMR) measurements, where the method comprises: conducting a first NMRmeasurement using a first predetermined set of measurement parameters;comparing the first NMR measurement results to a predetermined set ofcriteria applicable for different fluid types to estimate candidatetypes of fluids that may have produced the first NMR measurementresults; selecting an appropriate type of contrast mechanism and acorresponding second set measurement parameters for the estimated typesof fluids; and conducting a second NMR measurement using the second setof parameters to increase the accuracy of the fluid typing determinationin case the second set of parameters is different from said first set ofparameters. In a preferred embodiment, the first and the second set ofparameters correspond to one or more of the DSM, EDM, SSM, TPM, and ICAMfluid typing methods, as described below.

[0019] In another aspect, the present invention is directed to acomputer storage medium storing a software program to be executed on acomputer, comprising: a first software application for capturing NMRdata concerning a first measurement; a second software application, forcomparing the first measurement data to pre-set rules determining theoptimum contrast mechanism for use in the environment; and a thirdsoftware application, for providing a predetermined set of measurementparameters according to the determined optimum contrast mechanism.

[0020] In another aspect, the present invention is an apparatus forfluid typing of a geological environment using nuclear magneticresonance (NMR) measurements comprising: a logging tool capable ofconducting NMR measurements in a borehole; data storage for storing NMRlog data corresponding to one or more NMR measurements each measurementusing a predetermined set of measurement parameters; a computerprocessor configured to execute a software application program forselecting from NMR log data an optimum contrast mechanism andcorresponding measurement parameters for fluid typing of the geologicalenvironment; and a measurement cycle controller providing controlsignals to the logging tool for conducting NMR measurements based oninput from said processor. In a preferred embodiment, the apparatuscomprises a display for indicating the selection of measurementparameters to a human operator, and the logging tool has a dualwait-time sequencing capability.

BRIEF DESCRIPTION OF THE DRAWINGS

[0021] The present invention will be understood and appreciated morefully from the following detailed description taken in conjunction withthe drawings in which:

[0022]FIG. 1 illustrates the principles used for fluid typing in theDifferential Spectrum Method (DSM) of the present invention.

[0023]FIG. 2 shows log data and DSM data obtained through T₂-domainprocessing.

[0024]FIG. 3 is an example of using Time Domain Analysis (TDA) of DSMdata to find gas, oil, and water-wet zones.

[0025]FIG. 4 illustrates the principles used for fluid typing in theEnhanced Diffusion Method (EDM) of the present invention.

[0026]FIG. 5 shows an EDM application using T₂ domain analysis.

[0027]FIG. 6 is a comparison between the T₂ domain and TDA approachesfor determining residual oil saturation (ROS) in accordance with thepresent invention.

[0028]FIG. 7 shows a typical application range of EDM in accordance withthe present invention.

[0029]FIG. 8 illustrates the principles used for fluid typing in theShift Spectrum Method (SSM) used in accordance with the presentinvention.

[0030]FIG. 9 illustrates pulse sequences used in accordance with thepresent invention for the Total Porosity Method (TPM).

[0031]FIG. 10 illustrates a data processing mechanism used in accordancewith the present invention as part of the TPM.

[0032]FIG. 11 illustrates a T₂ spectrum obtained through TPM.

[0033]FIG. 12 is an example of using MnCl₂ in an Injecting ContrastAgent Method (ICAM) used in accordance with the present invention forobtaining Residual Oil Saturation (ROS) and porosity.

[0034]FIG. 13 is a partially pictorial, partially block diagramillustration of an apparatus for obtaining nuclear magnetic resonance(NMR) measurements in accordance with a preferred embodiment of thepresent invention.

[0035]FIG. 14 is a block diagram of the apparatus in accordance with apreferred embodiment, which shows individual block components forcontrolling data collection, processing the collected data anddisplaying the measurement results.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0036] A. The System

[0037] Reference is first made to FIG. 13, which illustrates anapparatus constructed and operative in accordance with a specificembodiment of the present invention for obtaining multi-contrast nuclearmagnetic resonance (NMR) measurements. The apparatus includes a firstportion 106, which is arranged to be lowered into a borehole 107 inorder to examine the nature of materials in the vicinity of theborehole.

[0038] The first portion 106 comprises a magnet or a plurality ofmagnets 108, which preferably generate a substantially uniform staticmagnetic field in a volume of investigation 109 extending in theformation surrounding the borehole. The first portion 106 also comprisesan RF antenna coil 116 which produces an RF magnetic field at the volumeof investigation 109.

[0039] A magnetic field gradient coil, or plurality of coils, 110generates a magnetic field gradient at the volume of investigation 109.This additional contribution to the magnetic field, which is essentialfor the fluid typing methods of the present invention using diffusion,has a field direction preferably collinear with the substantiallyuniform field and has a substantially uniform magnetic field gradient.The magnetic field gradient may or may not be pulsed, i.e., switched onand off by switching the dc current flowing through the coil or coils110. The magnet or magnets 108, antenna 116 and the gradient coil 110constituting portion 106 are also referred to as a probe.

[0040] The antenna together with a transmitter/receiver (T/R) matchingcircuit 120, which typically includes a resonance capacitor, a T/Rswitch and both to-transmitter and to-receiver matching circuitry, arecoupled to an RF power amplifier 124 and a receiver preamplifier 126. Apower supply 129 provides the dc current required for the magnetic fieldgradient generating coils 110. All the elements described above arenormally contained in a housing 128 which is passed through theborehole. Alternatively, some of the above elements may be located aboveground.

[0041] Indicated in a block 130 is control circuitry for the loggingapparatus including a computer 50, which is connected to a pulseprogrammer 60 that controls the operation of a variable frequency RFsource 36 as well as an RF driver 38. RF driver 38 also receives inputfrom the variable frequency source 36 through a phase shifter 44, andoutputs to RF power amplifier 124.

[0042] The output of RF receiver amplifier 126 is supplied to an RFreceiver 40 which receives an input from a phase shifter 44. Phaseshifter 44 receives an input from variable frequency RF source 36.Receiver 40 outputs via an A/D converter with a buffer 46 to computer 50for providing desired well logging output data for further use andanalysis. Pulse programmer 146 controls the gradient coil power supply129 enabling and disabling the flow of current, and hence the generationof static or pulsed field gradients, according to the commands of thecomputer 50. Some or all of the elements described hereinabove as beingdisposed in an above-ground housing, may instead be disposed belowground.

[0043]FIG. 13 depicts one embodiment of the apparatus used in accordancewith the present invention. In an alternative preferred embodiment, inaccordance with the present invention, various models of the MRIL® toolto Numar Corporation, or other tools known in the art, can be usedinstead. FIG. 14 is a block diagram of a generic system used inaccordance with the present invention, and shows individual blockcomponents for controlling data collection, processing the collecteddata and displaying the measurement results. In FIG. 14 the tool'selectronic section 30 comprises a probe controller and pulse echodetection electronics. The output signal from the detection electronicsis processed by data processor 52 to analyze the relaxationcharacteristics of the material being investigated. The output of thedata processor 52 is provided to the parameter estimator 54. Inaccordance with the present invention, data processor 52 operates inconjunction with parameter estimator 54 to determine an optimal contrastmechanism to be used for fluid typing in the particular boreholeenvironment. As discussed in more detail below, several differentcontrast mechanisms can be used in a preferred embodiment. The selectionof a suitable contrast mechanism by the data processor is thentranslated into the selection of a corresponding data acquisitiontechnique, and/or a different set of measurement parameters.

[0044] Dependent on the selected data acquisition technique, measurementcycle controller 55 provides an appropriate control signal to the probe.The processed data from the log measurement is stored in data storage56. Data processor 52 is connected to display 58, which is capable ofproviding a graphical display of one or more measurement parameters,possibly superimposed on display data from data storage 56. Accordingly,the selection of the optimal contrast mechanism for a particularmeasurement can be done by a human operator, or automatically, pursuantto a pre-set number of rules.

[0045] The components of the system of the present invention shown inFIG. 14 can be implemented in hardware or software, or any combinationthereof suitable for practical purposes. Details of the structure, theoperation and the use of logging tools, as illustrated in FIGS. 13 and14 are also discussed, for example, in the description of the MRIL® toolto Numar Corporation, and in U.S. Pat. Nos. 4,717,876; 4,717,877;4,717,878; 5,212,447; 5,280,243; 5,309,098; 5,412,320; 5,517,115,5,557,200 and 5,696,448, the contents of which are incorporated hereinfor all purposes.

[0046] In a preferred embodiment of the present invention the selectionof the optimum contrast mechanism for use in fluid typing in aparticular borehole environment is done by comparing results from afirst NMR measurement to a predetermined set of criteria applicable fordifferent fluid types. The criteria used in a preferred embodiment arebased on the theoretical models, which are discussed in further detailnext, as well as other types of measurements, prior experience, andother available information. At this stage, the apparatus of thisinvention determines broadly the type of fluids that may have producedthe first NMR measurement results and then, if necessary, selects theappropriate type of contrast mechanism and corresponding measurementparameters to possibly increase the accuracy of the fluid typingdetermination. In some instances, this may lead to a second measurementpass with a different set of measurement parameters. In a preferredembodiment, the selection criteria can be implemented in software, usinga rule based (i.e., if . . . then) approach in accordance with themodels discussed next. Preferably, the software used in the presentinvention is stored in a computer storage medium for execution on acomputer, such as data processor 52.

[0047] In a specific embodiment, the fluid typing program of the presentinvention comprises: a first software application for capturing NMR dataconcerning a first measurement; a second software application, forcomparing the first measurement data to pre-set rules determining theoptimum contrast mechanism for use in the environment; and a thirdsoftware application, for providing a predetermined set of measurementparameters according to the determined optimum contrast mechanism.

[0048] B. The Methods

[0049] In accordance with the present invention, fluid typing fordetecting and quantitatively measuring volumes occupied by brine, gas,and oil is done using several different methods, which are based onnuclear magnetic resonance (NMR) logging data. In particular, themethods of the present invention include Differential Spectrum Method(DSM), Enhanced Diffusion Method (EDM), Shifted Spectrum Method (SSM) intransverse relaxation time (T₂) domain or in spin-echo time domain(i.e., Time Domain Analysis; TDA), Total Porosity Measurement (TPM), andInjecting Contrast Agent Method (ICAM). Generally, DSM is used inaccordance with the present invention for gas and light oil; EDM is usedfor medium oil; SSM for gas and oil; TPM for bound water, includingclay-bound water and capillary-bound water, and movable fluids; and ICAMfor residual oil saturation (ROS) measurements. Each of these methodsand the associated contrast mechanisms are discussed in more detailnext. A brief summary of the contrast mechanisms used in accordance withthe present invention is presented next to help understand theindividual fluid typing methods.

[0050] Contrast Mechanisms

[0051] (a) The HI Contrast

[0052] The HI contrast associated with a particular molecule is afunction of the molecule's ass density, as well as the number ofhydrogen nuclei (protons) in the molecule. For a pure hydrocarbon, ithas been shown (see, e.g., Kleinberg, R. L., and Vinegar, H. J.: “NMRProperties of Reservoir Fluids,” The Log Analyst (November-December,1996) that

HI=ρ*n _(H)/0.11*MW  (1)

[0053] where ρ, MW, and n_(H) are mass density, molecular weight, andnumber of hydrogen atoms in the molecule, respectively. The above Eq.(1) has been modified the equation for oil:

HI=ρ*[R/(12.011+1.008R)]/0.11  (2)

[0054] where R is the ratio of hydrogen atoms to carbon atoms in theoil. For additional information, see, for example, Lo, S. W., et al.:“Some Exceptions to Default NMR Rock and Fluid Properties,” paper FFpresented at the 39^(th) Annual SPWLA Logging Symposium, Keystone,Colo., U.S.A., May 26-29, 1998, which is incorporated herein forbackground.

[0055] (b) Relaxation Times Contrasts

[0056] The contrasts of the relaxation times (T₁and T₂) result fromdifferent relaxation mechanisms that dominate in the fluids. The T₂ of afluid in a rock has been expressed as

1/T ₂=1/T _(2S)+1/T _(2B)+1/T _(2D)  (3)

[0057] where T_(2S) is the contribution from the surfaces of the porewall and the clays, T_(2B)is the contribution from the bulk fluid, andT_(2D) is a term related to molecular diffusion in a magnetic gradientfield. This gradient is either an external gradient, such as the linealgradient produced by an MRIL® tool, or an internal gradient from clays.Bulk relaxation (T_(2B) ) is from either the magnetic dipole-dipole (DD)interaction for liquids or the spin-rotation (SR) interaction for gases.For a liquid in a low magnetic field from the MRIL® tool, the T_(2B)component is given by

(1/T ₂)_(DD)˜γ⁴*τ_(c) *r ⁻⁶  (4)

[0058] where γ is the proton gyromagnetic ratio, τ_(c) is the rotationalcorrelation time, and r is the distance between the spins.

[0059] For a gas, the T_(2B) component is given by the expression

(1/T ₂)_(SR) ˜I*T*C ² _(eff)*τ_(J)  (5)

[0060] where I is the moment of inertia of the molecule, C_(eff) is theeffective spin-rotational coupling constant, and τ_(J) is theangular-momentum correlation time. For background information, seeBloembergen, N., Purcell, E. M., and Pound, R. V.: “Relaxation Effectsin Nuclear Magnetic Resonance Absorption,” Physical Review, (1948) 73,679.

[0061] The bulk relaxation of oil is a main contribution to T₂ for awater-wet reservoir. The relationship between the T₂ of an oil and theviscosity of the oil has been expressed as

T ₂=1.2*(T/298*η)^(0.9)  (6)

[0062] See Morriss, C. E., et al.: “Hydrocarbon Saturation and ViscosityEstimation from NMR Logging in the Belridge Diatomite,” The Log Analyst(March-April, 1997). Equation 6 is valid only for dead oil and for oilwith uni-exponential decay. For oil having a distribution of T₂ values,T₂ in the equation should be considered as the geometric mean of thedistribution.

[0063] The surface term T_(2S) in Eq. (3) above is given by theexpression:

T _(2S)=(ρ₂ *S/V _(p))⁻¹  (7)

[0064] where ρ₂ is the NMR surface relaxivity for T₂, V_(p) is the porevolume, and S is the surface of the pore or clay. For a sphere, S/V_(p)is 3/r, and r is the pore radius. In a fast-diffusion case, thisequation sets up a relationship between the T₂ distribution and a poresize distribution. For background, see, e.g. Kenyon, W. E.:“Petrophysical Principles of Applications of NMR Logging,” The LogAnalyst (March-April 1997).

[0065] When using a Carr-Purcell-Meiboom-Gill (CPMG) pulse sequence andexisting a linear gradient G, the diffusion term in Eq. (3) is given by

T _(2D)=12/[D*(γ*TE*G)²]  (8)

[0066] where D is a self-diffusion coefficient, and TE is anecho-spacing time.

[0067] The T_(2D) term shown in Eq. (8) is the only term in Eq. (3) thatcan be controlled by the user of an MRIL® tool. In particular, inaccordance with the present invention, the user can change T_(2D) byadjusting the TE and G parameters of the tool. Details concerning themodification of these parameters are discussed in several patents to theassignee of the present application, which are incorporated by referenceherein.

[0068] In accordance with the present invention, in a water-wetreservoir, the T₂ parameter of the brine phase is generally determinedby T_(2S); the T₂ of oil is obtained from T_(2B), and the T₂ of gas isapproximately equal to T_(2D) .

[0069] The T₁ of a formation fluid is described by

1/T ₁=1/T _(1S)+1/T _(1B)  (9)

[0070] A diffusion term is not included in this equation becausediffusion involves a spin dephasing process, which is a T₂ process.

[0071] The equations for T_(1B) for bulk liquids and gas in the lowmagnetic field are analogous to Eq. 4 and 5 for T_(2B). T_(1S)is thesurface relaxation contribution, and is given by

T _(1S)=(ρ₁ *S/V _(p))⁻¹  (10)

[0072] where ρ₁ is the surface relaxivity for T₁. For a gas, T₁ isgenerally controlled by the T_(1B) component. As known in the art, T₁can also be described by the following equation:

T ₁=2.5*10³ *ρ/T ^(1.17)  (11)

[0073] where T₁ is in seconds, the density ρ is in g/cm³, and thetemperature (T) in degrees Kelvin. This equation reveals thattemperature and pressure (the density term in the equation is related topressure) have opposite effects on T₁.

[0074] T₁ of gas is very long because of the small angular-momentumcorrelation time (τ_(J)) of gas. In a water-wet reservoir, T₁ of oil isobtained from bulk relaxation and can be written as

T ₁1.2*T/298*η  (12)

[0075] T₁ of brine is determined by the surface term. The T₁/T₂ ratio ofbrine ranges from approximately 1 to 1.5. For additional background, seefor example Kleinberg, R. L., et al.: “Nuclear Magnetic Resonance ofRocks: T₁ vs. T₂,” paper SPE 26470 presented the 1993 SPE AnnualTechnical Conference and Exhibition, Houston, Tex., U.S.A., Oct. 3-6,1993.

[0076] (c) Diffusion Contrast

[0077] It is known in the art that the contrast of D generally dependson molecular mobility. Hence, D is a function of temperature T, pressureP, and the environment, in which the diffusion molecule exists. Thediffusion relaxation mechanism depends on the diffusion of molecules inmagnetic field gradients, such as those generated by the MRIL® tool.Ordinarily, diffusion is a predominant relaxation mechanism only forgas. For the fast-diffusion case, D of gas is given by the knownexpression

D _(g)=8.5*10⁻⁷ *T ^(0.9)/ρ  (13)

[0078] D of oil is

D_(o)=1.3T/298*η  (14)

[0079] and D of movable water (mw) is

D _(mw)=1.2T/298*η  (15)

[0080] Generally, gas and water each have only one value of D for acertain T and P. However, an oil has a distribution of D because of themany different types of molecules in the oil. In oil, the D_(o) in Eq.(14) should be considered, in accordance with the present invention, asthe value of the geometric mean of this distribution.

1. The Differential Spectrum Method (DSM)

[0081] In principle, DSM is a T₁-contrast weighed method. Theinformation in Tables 1 and 2 shows that gas and light oil each have aT₁ much larger than that of brine. Hence, in accordance with the presentinvention, the method is used for typing gas and light oil. For adetailed discussion of aspects of this method, the reader is directed toU.S. Pat. Nos. 5,497,087 and 5,498,960 to Vinegar et al., and toco-pending patent applications Ser. Nos. 08/822,567 and 09/270,616 tothe assignee of the present application, which are hereby incorporatedby reference.

[0082] Magnetization in a CPMG spin echo train for a reservoir havingthree phase (brine, gas, oil) can be described by $\begin{matrix}\begin{matrix}{{M\left( {n*{TE}} \right)} \propto \quad {{\left\lbrack {1 - {\exp \left( {{- T_{W}}/T_{1b}} \right)}} \right\rbrack*{\exp \left( {{- n}*{{TE}/T_{2{Ab}}}} \right)}} +}} \\{\quad {{{HI}_{g}*\left\lbrack {1 - {\exp \left( {{- T_{W}}/T_{1g}} \right)}} \right\rbrack*{\exp \left( {{- n}*{{TE}/T_{2{Ag}}}} \right)}} +}} \\{\quad {{HI}_{o}*\left\lbrack {1 - {\exp \left( {{- T_{W}}/T_{1o}} \right)}} \right\rbrack*{\exp \left( {{- n}*{{TE}/T_{2{Ao}}}} \right)}}}\end{matrix} & (16)\end{matrix}$

[0083] where A, b, g, and o in the subscripts represent apparent, brine,gas, and oil, respectively, and n is echo number. According to thisequation and the values in Table 2, the brine phase can be eliminatedand the oil and gas phases can be still left in a differential echotrain from two CPMG acquisition data if T_(W1)>>T_(1b) andT_(W2)>>T_(1b) but T_(W1)>T_(W2)˜T_(1g) and T_(W1)>T_(W2)˜T_(1o).

[0084] For a Gulf of Mexico sandstone reservoir, it has been suggestedthat optimum T_(W1) and T_(W2) values are 1 second and 8 seconds,respectively. This experimental result has been suggested in, forexample, Akkurt, R., Prammer, M. G., and Moore, M. A.: “Selection ofOptimal Acquisition Parameters for MRIL Logs,” The Log Analyst(November-December 1996). When such T_(W)s are used in CPMG pulsesequences, the brine signal can be eliminated by taking the differenceof the two echo trains. The resulting hydrocarbon signals in thedifference can be still large. The remaining oil and gas signals arevery well separated from each other in a T₂ spectrum.

[0085]FIG. 1 illustrates the principle of the DSM used for fluid typingin accordance with the present invention. In FIG. 1(a), all three phaseshave a fully polarized T₂ spectrum at the long T_(W1). In FIG. 1(b), thebrine is still fully polarized, but the oil and gas are partiallypolarized at the T_(W2) FIG. 1(c) is the difference between the spectrain FIGS. 1(a) and 1(b), and shows the reduced and separated oil and gassignals.

[0086] DSM Data Acquisition and Data Processing

[0087] The data needed for DSM processing in accordance with the presentinvention consists of two spin echo trains acquired with two differentT_(W) CPMG pulse sequences. The TW's that are used must satisfy thefollowing conditions: T_(W1)>>T_(W2)>>T_(1b), T_(W2)<˜T_(1o),T_(W2)<˜T_(1g), T_(W1)˜2T_(1o), and T_(W1)˜2T_(1g). The TE parameter ischosen in a preferred embodiment to be approximately 1 ms to limitdiffusion influences on T₂. The number of echos depends on the longestT₂ (T_(2L)) in the formation, and is chosen in a preferred embodiment tosatisfy the condition (n*TE)≧T_(2L).

[0088] As known in the art, in the DSM, data is processed either in a T₂domain or in a time domain. The processing done in a time domain isreferred to as a time domain analysis (TDA).

[0089] In accordance with the present invention, processing in the T₂domain analysis involves inverting two spin echo trains to two T₂spectra and then subtracting one spectrum from the other. The process isas illustrated in FIG. 1. The inversion algorithm used in a preferredembodiment is known in the art and is discussed, for example in Prammer,M. G.: “NMR Pore Size Distributions and Permeability at the Well Site,”paper SPE 28368 presented at the 1994 SPE Annual Technical Conferenceand Exhibition, New Orleans, La., U.S.A., Sep. 25-28, 1994.

[0090] In accordance with the present invention, TDA processing methodis preferred to T₂-domain processing for detecting gas. The first stepin the TDA processing method is to obtain the echo difference from twoT_(W) spin echo trains. Careful T_(W) selection ensures that the echodifference contains only gas and light-oil signals. In a preferredembodiment, two matched filters are built based on the T₁s and the T₂sparameters of the oil and the gas:

f(t)_(o)=[exp(−T _(W1) /T _(1o))−exp(−T _(W2) /T _(1o)]*exp(−t/T_(2o))  (17)

[0091] and

f(t)_(g) =HI _(g)*[exp(−T_(W1) /T _(1g))−exp(−T _(W2) /T _(1g]*exp(−)t/T _(2g))  (18)

[0092] Use of these filters on the echo difference d(t) allowsoil-filled porosity (P_(o)) and gas-filled porosity (P_(g)) to beobtained through the matrix equation

[f(t)_(o) f(t)_(g) ]*[P _(o) P _(g)]⁻¹ 32 d(t)  (19)

[0093] For a more detailed description of the method, the reader isdirected to U.S. patent application Ser. No. 08/822,567 to the assigneeof the present application, which is incorporated herein for allpurposes. The oil and gas porosities obtained through Eq. 19 are morerobust than those from T₂ domain analysis, which usually uses more thanten T₂ values (bins) to obtain ten corresponding porosity solutions.

[0094] In accordance with the present invention, DSM can be used fordetermining gas volume. See Akkurt et al. “NMR Logging of Natural GasReservoirs,” Paper N presented at the 36^(th) Annual SPWLA LoggingSymposium, Paris, France, Jun. 26-29, 1995, which reported using datafrom a gradient-based MRIL®—C logging tool, to identify the gas phase ina Gulf of Mexico sandstone reservoir. FIG. 2 shows some of the log dataand some of the DSM data obtained through T₂-domain processing. Thefirst three tracks (from the left) contain the gamma ray (GR), inductionresistivity, and neutron and density logs, respectively. The T₂distributions (spectra) for T_(W)=6 and 3 seconds are displayed inTracks 4 and 5, and the difference of the two T₂ spectra (differentialspectrum) is shown in Track 6. The signals in the differential spectrumrange from approximately from 32 to 64 ms, which is in the range of gassignal for this tool with acquisition parameter (TE) used and formationtemperature that was encountered. All information indicates agas-bearing zone in the top section of this presentation.

[0095] In accordance with the present invention, the T_(W) selectionsmust be optimized for he specific case. For example, it was determinedthat the 3 and 6 seconds in the case illustrated above must be replacedwith data obtained with T_(W) values of 8 seconds and 1 seconds forbetter results for gas detection in the Gulf of Mexico.

[0096] Generally, T₂ domain analysis on DSM data is not sensitive to thegas signal because he signal is weak and is usually suppressed in thebound water region of a T₂ spectrum. TDA has been applied on DSM datafrom a highly laminated Gulf of Mexico turbidite invaded with syntheticoil filtrate. It has been determined that the conventional T₂ domainanalysis did not clearly detect the gas signal. However, TDA did showunambiguously both heavy filtrate invasion and the presence of gas wheregas saturation was very low.

[0097]FIG. 3 is an example of using TDA of DSM data to find gas, oil,and water-wet zones in accordance with a specific embodiment of thepresent invention. In this figure, the first two tracks of the logpresent logging-while-drilling (LWD) gamma ray and resistivity data, andthe third track plots effective porosity obtained by TDA. The gas/oilcontact (GOC) and oil/water contact (OWC) were identified by TDA. Theecho difference for the gas, the oil, and the brine zone are shown inFIGS. 3(a), 3(b), and 3(c), respectively. The echoes in 3(a) and 3(b)were fitted by the matched filters shown as Eqs. 17 and 18 for theporosities occupied by the gas and the oil.

[0098] Because the DSM requires a large T₁ contrast, a large diffusioncontrast, and a good signal-to-noise ratio (S/N), viable candidates forDSM applications are gas and light-oil reservoirs. In accordance withthe present invention, the bulk viscosity of the reservoir oil shouldpreferably be less than about 1 cp, and the apparent gas porosity shouldbe greater than about 1 porosity unit (p.u.) for optimal results.

2. The Enhanced Diffusion Method (EDM)

[0099] In accordance with the present invention, the EDM is used fortyping medium oil. In principle, the EDM uses diffusion contrast fordetermining the porosity occupied by a medium oil (i.e., 1 cp<η<50 cp).According to Eq. 3, T₂ is smaller than each of T_(2B), T_(2S), andT_(2D). In accordance with the present invention, the parameters G andTE of the measurement device can be adjusted to make T_(2D) a smallvalue for any fluid phase. Through such an adjustment, an upper boundfor the T₂ spectrum of any phase can be established. Because T_(2D)depends on D, which is a function of temperature and phase, the upperbound shifts according to the phase. For example, at 200° F., the valuesof D for brine, gas, and 10 cp oil are 7.7×10⁻⁵, 100×10⁻⁵, and0.1598×10⁻⁵ cm²/s, respective. If G=18 gauss/cm and TE=4.8 ms, Eq. 8shows that the upper bounds for T_(2D) for brine, oil, and gas areT_(2D,b)=29.2 ms, T_(2D,o)=1,406 ms, and T_(2D,g)=2.25 ms. Hence,T_(2D,g) is located low end of a T₂ spectrum and T_(2D,o) is located thehigh end of the spectrum, and there is a gap between the T_(2D,o) andthe T_(2D,b). Because of the influence of noise, the actual upper boundfor a brine phase can be ˜2*T_(2D,b).

[0100] In the numerical example being considered here, the oil and thebrine are well separated because T_(2,o)=[(1/T_(2D,o))+(1/T_(2B,o))]=140ms>>60 ms=˜2*T_(2D,b). Oil-filled porosity is obtained by integratingthe area under the peak.

[0101] In summary, the EDM uses differences in diffusion coefficientsamong the phases for setting up T₂ upper bounds for the phases. As longas the T₂ of an oil is larger than ˜2*T_(2D,b), the oil-filled porositycan be obtained from its separated peak.

[0102]FIG. 4 illustrates the principle of the EDM. FIG. 4(a) depicts aT₂ spectrum without diffusion influence (G*TE˜0). FIG. 4(b) shows the T₂spectrum with diffusion influence (G*TE>>0). The vertical line in FIG.4(b) is the T_(2D,b), to the right of which is a separated oil peak.

[0103] EDM Data Acquisition and Processing

[0104] If only a qualitative analysis is needed, EDM data are acquiredin accordance with the present invention with T_(W)˜3*T_(1,Max) whereT_(1,Max) is the maximum value of a T₁ spectrum for all phases, and witha large TE for separating oil from the other phases. However, for aquantitative analysis and a fast logging speed, in accordance with thepresent invention EDM are acquired with two T_(W)s (typically, 5000 msand 500 ms) and a long TE (usually 4.8 ms) in two CPMG pulse sequences.In accordance with a preferred embodiment of the present invention adual wait-time pulse sequence is run to collect the required NMRmeasurement data. Dual wait-time sequencing capability not requiringseparate logging passes is provided by the MRIL® tool as described, forexample, in co-pending application Ser. No. 08/822,567 assigned to theassignee of the present application, which is incorporated herein forall purposes. In alternative embodiments of the present invention, asingle wait-time pulse sequence can also be used, since there will be T₂separation between the two phases regardless of any T₁ contrast. Becausethe method to acquire data is the same as the one used in the DSM, thedata processes are nearly identical except that a correction for theshort component of T₁ of oil must be considered. More detail concerningthe EDM method is found in the co-pending patent application Ser. No.09/270,616, filed Mar. 17, 1999, the content of which is incorporatedherein by reference.

[0105] Because the oil targeted for detection by this method usually hasa T₁ distribution that includes a long component and a short component,two T₁ corrections must be made in accordance with the present inventionfor whether the processing is performed in T₂ domain or in time domain.In a specific embodiment, the first correction is applied to the long T₁component of the oil, which has a large D. The second correction isapplied to the short component (which has a small D) so that it mixeswith the water signal. In the second correction, the T₁ distribution ofthe oil is needed to determine the contributions of the shortcomponents. Details of the T₁ corrections can be found, for example inthe above application.

[0106] Applications

[0107] An EDM application in which T₂ domain analysis was used inaccordance with the present invention is shown in FIG. 5. In thisfigure, the gamma ray, resistivity, and porosity logs shown in Tracks 1,2, and 4 suggest a possible hydrocarbon zone at around X036. Track 3contains the differential spectrum from the EDM logs acquired withTE=3.6 ms and T_(w)=300 ms and 3,000 ms. The dashed vertical line inTrack 3 represents T_(2D,b=)44 ms. The oil signal is clearly seen to theright of this line. From the differential spectrum, a water/oil contactis identified at around X036, and 10% oil is produced in the surroundinginterval.

[0108]FIG. 6 is a comparison between the T₂ domain and TDA approachesfor determining residual oil saturation (ROS) in accordance with thepresent invention. Tracks 1 and 2 contain the gamma ray and resistivitylogs, while Track 3 displays the differential spectrum for T_(W)=5,000and 500 ms and TE=4.8 ms. Three apparent oil volumes are plotted inTrack 4. The solid and dotted curves represent the oil volumes obtainedfrom T₂ domain analysis using data acquired with T_(W)=5,00 ms and 5000ms for TE=4.8 ms and 3.6 ms, respectively. The dashed curve was obtainedfrom TDA on the data sets of TE=4.8 ms. In this example, these curvesdemonstrate that the two processing methods yield almost the same oilvolume.

[0109] It should be noted that from a quantitative point of view, theoil porosity from a T₂ domain analysis may not be very accurate becausethe value of T_(2D,b) can be influenced by an internal gradient.Accuracy can also be adversely affected by noise. Portion of brine's T₂can be larger than T_(2D,b). These considerations should be taken intoaccount in practical applications.

[0110] As noted above, the DSM provides typing of gas and light oil. TheEDM expands the fluid-typing range to medium oil. FIG. 7 shows a typicalapplication range of EDM. To plot this figure, Eq. 6, 8, and 14 are usedwith TE=3.6 ms, G=19.1 gauss/cm, T=200° F. If the oil-water T₂ contrastis chosen as 2, then the EDM can be applied to type oil with viscosityfrom approximately 0.4 to 40 cp, with the maximum contrast occurringbetween 4 and 10 cp.

[0111] In accordance with the present invention, the EDM can be appliedin carbonate reservoirs. Note that DSM typing may not give good resultsin such reservoirs because of long T₂ and T₁ components for the brinephase. This is an example of how the flexibility provided by the presentinvention enables accurate analysis of the formation fluids dependent onthe particular conditions.

3. The Shift Spectrum Method

[0112] In accordance with the present invention, the SSM is used for gasand oil typing. In principle, the SSM is also a diffusion contrastmethod and thus is suited for use with the gradient NMR tools. In apreferred embodiment, it applies two different TEs and a long T_(W)≧(2to 3)*T_(1,Max) in two CPMG pulse sequences. Relating to the T₂ spectrumthat results from the short TE, the T₂ spectrum from the long TE due todiffusion effect is shifted to the low end of the T₂, and the spectrumis also compressed. If the gas signal is shifted to the dead time of anMRIL tool when collecting long TE data, then the gas signal cannot bedetected in the long TE data; however, the gas signal is present in theshort TE data. By taking the difference between the long and short TEdata and ignoring the diffusion influence of brine and oil, only gassignal is obtained.

[0113] The net magnetization for the difference of the two CPMG trainsis $\begin{matrix}{{\Delta \quad {M(t)}} = {\Sigma \quad M_{0,{i = o},b,g}*\left\{ {{\exp \left\{ {{- t}*\left\lbrack {{1/T_{{2B},i}} + {D_{i}*{\left( {\gamma*T\quad E_{1}*G} \right)^{2}/12}} + {1/T_{{2S},i}}} \right\rbrack} \right\}} - {\exp \left\{ {{- t}*\left\lbrack {{1/T_{{2B},i}} + {D_{i}*{\left( {\gamma*T\quad E_{2}*G} \right)^{2}/12}} + {1/T_{{2S},i}}} \right\rbrack} \right\}}} \right\}}} & (20)\end{matrix}$

[0114] If TE₁=1.2 ms and TE₂=2.4 ms, and the values of the parameters inTable 2 are used, then $\begin{matrix}{{\Delta \quad {M(t)}_{g}} = {M_{0,g}*\exp \left\{ {{- t}*\left\lbrack {D_{i}*{\left( {\gamma*T\quad E_{1}*G} \right)^{2}/12}} \right\rbrack} \right\}}} & (21) \\\begin{matrix}{{\Delta \quad {M(t)}_{o}} = \quad {M_{0,o}*{\exp \left( {{- t}*{1/T_{{2B},o}}} \right)}*}} \\{\quad \left\{ {{\exp \left\{ {{- t}*\left\lbrack {D_{o}*{\left( {\gamma*T\quad E_{1}*G} \right)^{2}/12}} \right\rbrack} \right\}} -} \right.} \\{\quad \left. {\exp \left\{ {{- t}*\left\lbrack {D_{o}*{\left( {\gamma*T\quad E_{2}*G} \right)^{2}/12}} \right\rbrack} \right\}} \right\}} \\{\quad {\sim\quad 0}}\end{matrix} & (22) \\\begin{matrix}{\quad {{M(t)}_{b} = \quad {M_{0,b}*{\exp \left( {{- t}*{1/T_{{2S},b}}} \right)}*}}} \\{\quad \left\{ {{\exp \left\{ {{- t}*\left\lbrack {D_{b}*{\left( {\gamma*T\quad E_{1}*G} \right)^{2}/12}} \right\rbrack} \right\}} -} \right.} \\{\quad \left. {\exp \left\{ {{- t}*\left\lbrack {D_{b}*{\left( {\gamma*T\quad E_{2}*G} \right)^{2}/12}} \right\rbrack} \right\}} \right\}} \\{\quad {\sim\quad 0}}\end{matrix} & (23)\end{matrix}$

[0115] Hence, for these two TE values, when oil and brine diffusioninfluences on T₂ can be ignored, only gas signal is left in ΔM(t).

[0116]FIG. 8 illustrates the principle of SSM used as a fluid typingmethod in accordance with the present invention. The solid curve, shownas ‘a’ in the figure, represents the spectrum obtained when TE=1.2 ms,and the dashed curve, shown as ‘b’, represents the spectrum obtainedwhen TE=4.8 ms. The 40 ms peak in the solid curve is gas and is shiftedout in the 4.8 ms spectrum. The gas signal is found by subtracting thedashed curve from the solid curve.

[0117] Data Acquisition and Processing

[0118] Data for use in the SSM are usually acquired with TE set at 1.2and 3.6 ms and T_(W)=8s. This method has a much longer pulse cycle time,which is the time for acquiring two CPMG data sets. The cycle time isapproximately 16 seconds for SSM, but only 5.5 seconds for EDM. SSM datacan be processed in accordance with this invention by either T₂ domainanalysis or TDA. In a preferred embodiment, the processing is the sameas for the DSM, except that the matched filter in TDA for gas isdifferent because the diffusion influence on SSM must be considered.

[0119] Applications

[0120] In accordance with the present invention, the SSM can be appliedto determine gas signals. See, e.g. Mardon, D., et al.:“Characterization of Light Hydrocarbon-Bearing Reservoirs by GradientNMR Well Logging: A Gulf of Mexico Case Study,” paper SPE 36520presented at the 1996 SPE Annual Technical Conference and Exhibition,Denver, Colo., U.S.A., Oct. 6-9, 1996. In the above reference, TE=1.2and 2.4 ms is used in CPMG pulse sequences to obtain two T₂ spectra.Comparing the spectra and using gamma ray, resistivity, andneutron-density logs, it was found that the water and light-oil signalsremain, but the gas signal is shifted to below detectable levels for the2.4 ms data.

[0121] SSM dual-TE logging is more useful in a more viscous oil (η˜20cp). Such oil has a much smaller diffusion coefficient than water. Byusing the diffusion contrast between water and the more viscous oil, anempirical crossplot of T_(2I) and D can be created, whereT_(2I)=[1/T_(2B)+1/T_(2S)]⁻¹. See Coates, G. R., et al.: “Applying LogMeasurements of Restricted Diffusion and T₂ to Formation Evaluation,”paper P presented at the 36^(th) Annual SPWLA Logging Symposium, Paris,France, Jun. 26-29, 1995. The following two equations were used tocalculate T_(2I) and D from the data sets acquired with two TE values.

(1/T ₂)_(TE1)=1/T _(2I) +D*(γ*TE ₁ *G)²/12  (24)

(1/T ₂)_(TE2)=1/T _(2I) +D*(γ*TE ₂ *G)²/12  (25)

[0122] Water saturation and pore size are determined from the crossplot.This crossplot is applied to determine oil-filled porosity in a well inwestern Canada. A similar approach can be applied, but obtained T_(2I)and D from the spin-echo time domain to determine oil-filled porosity.

4. The Total Porosity Method (TPM)

[0123] The DSM, SSM, and EDM are specially designed and used inaccordance with the present invention for hydrocarbon typing. The TPMused in accordance with the present invention is good for distinguishingbrine-related porosity components: clay-bound water, capillary-boundwater, and movable water. See Prammer, M. G., et al.: “Measurements ofClay-Bound Water and Total Porosity by Magnetic Resonance Logging”,paper SPE 36522 presented at the 1996 SPE Annual Technical Conferenceand Exhibition, Denver, Colo., U.S.A., Oct. 6-9, 1996; and Coates, G.R., et al.: “Applying NMR Total and Effective Porosity to FormationEvaluation,” paper SPE 38736 presented at the 1997 SPE Annual TechnicalConference and Exhibition, San Antonio, Tex., U.S.A., Oct. 5-8, 1997.

[0124] Bound water saturation is a very important parameter forestimating formation production. To accurately determine the volume offormation occupied by immovable water, in accordance with the presentinvention, the fast decay signal, which arises mainly fromclay-bound-water, must be recorded. Recording this decay signal requiresa short TE and a good SNR.

[0125] In accordance with the present invention, a modified MRIL®—C toolcan be used along with pulse sequences, as shown in FIG. 9 in apreferred embodiment for the TPM. These pulse sequences have two parts.

[0126] The first part is a regular pulse sequence having a long T_(W)for full recovery of magnetization between measurements. This partusually uses a 1.2 ms echo spacing time, and acquires 400 echoes.Effective porosity is obtained from the data.

[0127] The second part is designed to obtain the clay-bound signal(T₂<2.5 ms). This part has a short T_(W) (20 ms), a short TE (0.6 ms), ashort echo train (8 to 10 echoes), and 50 pulse repetitions. The shortT_(W) can not provide a T₂ spectrum with full recovery, but it is longenough for full recovery of the clay-bound T₂. The TE=0.6 ms isprimarily used to resolve T₂ values less than or equal to 1 ms. Therepetitions is used to increase S/N of the clay-bound signal.

[0128] The data acquisition process provides two data sets withdifferent S/N. To obtain the total porosity, these two data sets must becombined. In a preferred embodiment, a T₂ inversion algorithm for thedata sets by using two inversions and a cutoff method is used. FIG. 10indicates how the data are processed. The data sets with high and lowS/N are inverted separately by fixing different T₂ values. Datacombination is accomplished simply by using the first four T₂ components(0.5, 1, 2, and 4 ms) from the short echo data and all of the componentsfrom 8 ms and up obtaining from the inversion of the long echo data.This method results in a T₂ distribution that is discontinuous aroundthe cutoff values, which are 4 and 8 ms.

[0129] Recently, an algorithm has been developed for simultaneousinversion of the data sets with different SNR. The resulting T₂ spectrumfor total porosity is continuous, and has more information on clay-boundwater.

[0130] In the T₂ distribution, the porosity occupied by clay-bound-wateris proportional to the area where T₂<2.5 ms. In a sandstone reservoir,the porosity occupied by capillary-bound-water is proportional to thearea in which 2.5 ms≦T₂≦35 ms; in a carbonate reservoir, these boundsare given by 2.5 ms≦T₂≦100 ms. The remainder of the area under thespectrum (i.e., T₂>35 ms for the sandstone and T₂>100 ms for thecarbonate) is proportional to the porosity occupied by movable fluids.

[0131]FIG. 11 is a T₂ spectrum obtained through TPM. This spectrum isdivided into the regions that correspond to clay-bound, capillary-bound,and movable water.

[0132] If only information about bound-water is needed, a short T_(W)and smaller echo number can be used because T₁ and T₂ of bound-water areshort. This application has been demonstrated with a CMR tool, usingTE=0.2 ms, T_(W)=0.25 s, and 165 echoes in a sandstone reservoir, andTE=0.2 ms, T_(W)=0.75 s, and 500 echoes in a carbonate reservoir.Logging with these parameters can be fast (3,600 ft/hr in sandstones and1,200 ft/hr in carbonates).

5. The Injecting Contrast Agent Method (ICAM)

[0133] The ICAM is a method for accurately determining residual oilsaturation (ROS) in open hole, although the need to inject a contrastagent can sometimes be an inconvenience. The most common agents used inthe ICAM are Mn-EDTA and MnCl₂. Through the invasion of dosed mud orthrough direct injection of the contrast agent, the agent mixes withformation brine. Because of the short T₂ of the resulting mixture, thesignal from the brine cannot be detected. However, the oil signal is notinfluenced by the agent and can be measured by an NMRL tool. Furtherdetails concerning this method can be found, for example in U.S. Pat.No.3,657,730, which is incorporated herein for all purposes.

[0134] Recently, a cheaper contrast agent (MnCl₂) and a faster NMRdoping and logging procedure have been discovered. See Horkowitz, J. P.,et al.: “Residual Oil Saturation Measurements in Carbonates With PulsedNMR Logs,” The Log Analyst (March-April 1997). In accordance with apreferred embodiment, this agent and procedure can be used to determineROS in a carbonate reservoir in west Texas. Mn⁺⁺ iron in the newcontrast agent has greater relaxivity for water protons than Mn-EDTA, soless dope is required. The reduction in time is possible because thereis no need to pack off and inject in the target zoom.

[0135] For determining ROS, the method of the present invention onlyreduces the T₂ of the MnCl₂-H₂O mixture to separate the oil signal. Fromthe oil and the mixture peaks, ROS and porosity can be obtained.

[0136]FIG. 12 is an example of using MnCl₂ in ICAM for obtaining ROS andporosity. Track 1 is a T₂ distribution (spectrum) for a “non-doped”well, and the Track 2 is a T₂ distribution (spectrum) for the “doped”well. Comparison of the two spectra reveals that the water signal isshifted to 10 ms to 20 ms, while the oil signal is still at 500 ms afterthe doping with MnCl₂. A T₂ cutoff value for the oil signal is foundfrom the T₂ distribution as 90 ms. The oil-filled porosity can beobtained from the total area of T₂>90 ms. Because MnCl₂ shifts only thewater signal, the total signal from the oil and the water providesporosity. Therefore, the ROS is the ratio of the oil-filled porosity tothe porosity.

[0137] Miscellaneous

[0138] Five NMR-based methods for fluid typing have been reviewed fromthe standpoint of principles, data acquisition and processing, andapplications, as used in preferred embodiments of the present invention.By using a suitable combination of these methods, the individualporosities occupied by clay-bound water, capillary-bound water, movablewater, gas, light oil, medium oil, and residual oil can be determinedwith high accuracy under different formation conditions.

[0139] It should be apparent that knowledge of formation conditions,such as formation temperature, formation pressure, and fluid viscosityare crucial in obtaining high-quality logging data, and in selecting theoptimum methods to be used in fluid typing. In particular, while thediscussion above focuses solely on NMR-based methods, various otherlogging methods to enhance the accuracy of the measurement and datainterpretation processes practiced in accordance with the presentinvention. For example, conventional neutron, density, sonic andresistivity logs can be used in addition to or in combination with themethods described above for improved results.

[0140] Although the present invention has been described in connectionwith the preferred embodiments, it is not intended to be limited tothese embodiments but rather is intended to cover such modifications,alternatives, and equivalents as can be reasonably included within thespirit and scope of the invention as defined by the following claims.

What is claimed is:
 1. A system for fluid typing of a geologicalenvironment using nuclear magnetic resonance (NMR) measurementscomprising: means for determining a set of parameters for a gradient NMRmeasurement, means for obtaining a pulsed NMR log using the determinedset of parameters; and means for selecting from the NMR log an optimumcontrast mechanism and corresponding measurement parameters for fluidtyping of the geological environment, wherein the selected contrastmechanism is based on at least one of: diffusion, relaxation, hydrogenindex and viscosity contrast.
 2. The system of claim 1, wherein the setof determined parameters comprises one or more of: the interecho spacingT_(E) of a pulsed NMR sequence, the magnetic field gradient G of the NMRmeasurement, and the wait time T_(W) of the NMR measurement.
 3. Thesystem of claim 1, wherein a diffusion contrast mechanism is based on atleast one of: T₁, T₂ contrasts.
 4. The system of claim 1, wherein themeans for obtaining a pulsed NMR log comprises a logging tool capable ofconducting multi-contrast NMR measurements.
 5. The system of claim 4,wherein the logging tool generates a gradient magnetic field in thegeological environment.
 6. The system of claim 1 further comprising adisplay for indicating the selection of measurement parameters to ahuman operator.
 7. The system of claim 1, wherein the means forobtaining a pulsed NMR log comprises a measurement cycle controllerproviding control signals to a logging tool for conducting NMRmeasurements based on input from said processor.
 8. A method ofdetermining fluid types present in a geological environment, comprisingthe steps of: providing a predetermined set of criteria applicable todifferent fluid types in the geological environment, the provided set ofcriteria being based on one or more of: theoretical models, one or moremeasurements concerning properties of the geological environment, orexperience with similar geological environments; making a firstmeasurement of the geological environment using a first predeterminedset of measurement parameters; comparing results of the firstmeasurement of the geological environment to the provided set ofcriteria applicable to different fluid types to estimate candidate typesof fluids that may have produced the results of the first measurement;and selecting a type of fluid contrast mechanism optimized for theestimated candidate types of fluids.
 9. The method of claim 8 furthercomprising the step of determining a second set of measurementparameters corresponding to the selected type of fluid contrastmechanism.
 10. The method of claim 9 further comprising the step ofconducting a second measurement using the determined second set ofmeasurement parameters.
 11. The method of claim 8, wherein the firstmeasurement comprises one or more of: neutron, density, sonic,resistivity and NMR measurements.
 12. The method of claim 9, wherein thestep of determining a second set of measurement parameters comprisesdetermining a set of parameters for an NMR measurement.
 13. The methodof claim 12, wherein the step of determining a set parameters for an NMRmeasurement comprises one or more of: the interecho spacing T_(E) of apulsed NMR sequence, the magnetic field gradient G of the NMRmeasurement, and the wait time T_(W) of the NMR measurement.
 14. Themethod of claim 10, wherein the second measurement is an NMRmeasurement.
 15. The method of claim 8, wherein the first measurementcomprises an NMR measurement in combination with one or more of:neutron, density, sonic and resistivity measurements.
 16. The method ofclaim 8, wherein the first measurement comprises an NMR measurement, andthe step of selecting a type of fluid contrast mechanism comprisesselecting one or more of the DSM, EDM, SSM, TPM, and ICAM fluid typingmethods.
 17. The method of claim 10, wherein the step of conducting asecond measurement using the determined second set of measurementparameters is performed upon determination that the second set ofparameters is substantially different from said first set of parameters.18. A system of determining fluid types present in a geologicalenvironment, comprising: means for providing a predetermined set ofcriteria applicable to different fluid types in the geologicalenvironment, the provided set of criteria being based on one or more of:theoretical models, one or more measurements concerning properties ofthe geological environment, or experience with similar geologicalenvironments; means for making a first measurement of the geologicalenvironment using a first predetermined set of measurement parameters;means for comparing results of the first measurement of the geologicalenvironment to the provided set of criteria applicable to differentfluid types to estimate candidate types of fluids that may have producedthe results of the first measurement; and means for selecting a type offluid contrast mechanism optimized for the estimated candidate types offluids.
 19. The system of claim 18 further comprising means fordetermining a second set of measurement parameters corresponding to theselected type of fluid contrast mechanism.
 20. The system of claim 19further comprising means for conducting a second measurement using thedetermined second set of measurement parameters. Nomenclature CMR=amagnetic resonance imaging logging tool from SchlumbergerCPM=Carr-Purcell-Meiboom-Gill spin echo pulse sequence D=apparentdiffusivity, cm²/s DSM=differential spectrum method EDM=enhanceddifferential method G=magnetic field gradient, G/cm HI=hydrogen indexrelative to water ICAM=injecting contrast agent method MRIL®=a magneticresonance imaging logging tool from NUMAR. mw=movable water MW=molecularweight NMRL=nuclear magnetic resonance logging ROS=residual oilsaturation S/N=signal-to-noise ratio SSM=shift spectrum method T₁=spinlattice relaxation time, i.e., longitudinal relaxation time, sT₂=spin-spin relaxation time, i.e., transversal relaxation time, sTDA=time domain analysis TE=echo spacing time, ms TPM=total porositymeasurement T_(W)=wait time, s Subscripts 0=an equilibrium stateA=apparent B=bulk b=brine c=correlation D=diffusion DD=dipole-dipoleinteraction eff=effective g=gas H=hydrogen I=intrinsic J=angularmomentum L=longest Max=maximum o=oil p=pore S=surface